Downhole Solid State Pumps

ABSTRACT

A pump includes a solid state pump including a solid state actuator actuatable to pressurize a hydraulic fluid, and a secondary pump in fluid communication with the solid state pump via a fluid circuit. The secondary pump is actuatable with the hydraulic fluid received from the solid state pump, and actuating the secondary pump draws in an external fluid into the secondary pump, pressurizes the external fluid within the secondary pump, and discharges a pressurized external fluid.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefits of U.S. Provisional Application62/688,731, filed Jun. 22, 2018, the entirety of which is incorporatedherein.

BACKGROUND

In the oil and gas industry, wellbores are drilled for the purpose ofproducing hydrocarbons from subterranean formations. Some wellboresproduce liquid hydrocarbons, while others primarily produce gaseoushydrocarbons. Over time, gas production wells can fill with wellboreliquids, such as water, condensate, and/or liquid hydrocarbons. Thesewellbore liquids create an impediment to gas flow and, in more severecases, can entirely stop gas production.

One way to deal with accumulating wellbore liquids in gas wells is toinstall an artificial lift system to remove the wellbore liquids.Artificial lift systems take advantage of a forced pressure differentialbetween the casing that lines the wellbore and production tubingextended into the casing to extract the liquids. The pressuredifferential is created by sealing the well and subsequently actuating asurface valve to systematically remove liquids from the well.

Plunger lift and pumping systems are examples of common artificial liftsystems used to remove wellbore liquids from gas wells. While effectiveunder certain circumstances, these systems may not be capable ofefficiently removing wellbore liquids from long and/or deep gas wells,from wells that are deviated, or from wells in which the gaseoushydrocarbons do not generate at least a threshold pressure. Moreover,pumping systems suffer from reliability issues and/or considerableinstallation/deployment costs since a workover rig is typically requiredfor intervention.

Plunger lift systems are dependent on reservoir pressure and can onlyremove a limited amount of liquid per day. Pumping systems are typicallyemployed when water volumes are high or reservoir pressure is too lowfor a plunger application. Common pump types used include sucker rodpumps, electric submersible pumps (ESPs), progressive cavity pumps(PCPs), and hydraulic pumps. Conventional sucker rod pumps and PCPs arepositive displacement pumps that can produce high head at variousvolumetric throughputs, and do not require a multitude ofstages/sections to achieve a desired head. Rod pumps are typicallypowered by reciprocating rods, and the theoretical production volume islimited by the maximum number of rod strokes per minute that can beachieved without failing the surface pumping unit or the downholeequipment. PCPs are typically powered with rotating rods, and thetheoretical production volume is limited by the maximum rpm at which therods can be rotated without failing the surface driver(s) or downholeequipment.

The mechanical connection from the pumps to surface can also limit theapplication depth of a rod pump or PCP system. Additionally, rods canwear and create holes in the production tubing in which they areinstalled, particularly in deviated or horizontal wells. Electricsubmersible PCPs have been developed, but are still depth limited by themaximum head that can be generated from the rotor-in-stator design.

Significant gas and oil reserves are at stake if liquids cannot beeconomically produced from gas wells, and the foregoing issues withplunger lift and pumping systems can make economical hydrocarbonproduction impracticable. What is needed is a pumping system that can beimplemented in deep wells, that is less expensive to deploy/replace, andis more resistant to deviated/tortuous trajectories.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent disclosure, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, withoutdeparting from the scope of this disclosure.

FIG. 1 is a schematic diagram of an example well system that mayincorporate one or more principles of the present disclosure.

FIG. 2 is an enlarged partial cross-sectional view of a portion of thewell system of FIG. 1, including the positive-displacement solid statepump, according to one or more embodiments of the present disclosure.

FIG. 3 is an enlarged schematic view of another example embodiment ofthe positive-displacement solid state pump as included in the wellsystem of FIG. 1.

FIG. 4 is a schematic diagram of an example positive-displacement solidstate pump, according to embodiments of the present disclosure.

FIGS. 5A and 5B depict example operation of the solid state pump of FIG.4.

FIG. 6 is an enlarged schematic view of another example pump that may beused in the well system of FIG. 1.

FIG. 7 is an enlarged schematic view of another example pump that may beused in the well system of FIG. 1.

DETAILED DESCRIPTION

The present disclosure is generally related to systems and methods forartificial lift in a wellbore and, more specifically, to systems andmethods that utilize a downhole solid state pump to remove wellboreliquids from the wellbore.

The embodiments disclosed herein describe a pump that may be used in awell system to extract wellbore liquids from a wellbore. The pump may beconveyable into production tubing extended within the wellbore, and thepump may include a solid state pump and a secondary pump in fluidcommunication with the solid state pump via a fluid circuit. The solidstate pump may include a solid state actuator actuatable to pressurize ahydraulic fluid, and the secondary pump may be actuatable with thehydraulic fluid received from the solid state pump. A control system maybe communicably coupled to the pump to control its operation. Actuatingthe secondary pump may draw in a wellbore liquid into the secondarypump, pressurize the wellbore liquid within the secondary pump, anddischarge a pressurized wellbore liquid into the production tubing forproduction to a surface location.

FIG. 1 is a schematic diagram of an example well system 100 that mayincorporate one or more principles of the present disclosure. Asillustrated, the well system 100 includes a wellhead 102 arranged at asurface location 104 and a wellbore 106 that extends from the wellhead102 and through one or more subterranean formations 108. In someembodiments, the wellhead 102 may be replaced with a surface rig (e.g.,a derrick or the like), a service truck, or other types of surfaceintervention systems. The wellbore 106 may be lined with one or morestrings of casing 110, and a production tubing 112 may be arranged orotherwise extended within the casing 110. In some applications, thecasing 110 and the production tubing 112 may both extend from andotherwise be “hung off” the wellhead 102.

As used herein, the term “production tubing” can refer to any pipe orpipe string known to those skilled in the art, such as casing, liner,drill string, injection tubing, coiled tubing, a pup joint, a buriedpipeline, underwater piping, or aboveground piping.

In some applications, as illustrated, the wellbore 106 may deviate fromvertical at some point and terminate at a toe 114 in a slanted orhorizontal portion of the wellbore 106. Those skilled in the art willreadily appreciate that the principles of the present disclosure areapplicable to wells having a variety of wellbore directionalconfigurations including vertical wellbores, deviated wellbores,horizontal wellbores, slanted wellbores, multilateral wells,combinations thereof, and the like.

As illustrated, the well system 100 may include a pump 116 conveyableinto the production tubing 112 and operable as an artificial lift systemto remove wellbore liquids from the wellbore 106. In some embodiments,the pump 116 may comprise a positive-displacement solid state pump.Accordingly, the pump 116 may be referred to herein as “the solid statepump 116.” In some embodiments, the well system 100 may include alubricator 118 (shown in dashed lines) arranged at the surface location104 in conjunction with the wellhead 102. The lubricator 118 may be usedto receive and inject the solid state pump 116 into the wellbore 106and, more particularly, within the production tubing 112. The lubricator118 may also be used to remove the solid state pump 116 from thewellbore 106 as needed.

As compared to traditional artificial lift systems, the solid state pump116 may be small enough to be introduced into the wellbore 106 via thelubricator 118. This may prove advantageous in allowing the solid statepump 116 to be located within the wellbore 106 without depressurizing orkilling the well system 100, and/or while containing wellbore fluidswithin the wellbore 106. Moreover, this may increase efficiency ofoperations by decreasing the time required to introduce or remove thesolid state pump 116 into/from the wellbore 106. The solid state pump116 may also be short enough to be conveyed past deviations in mostwellbores. Such deviated regions might obstruct or retain longer orlarger-diameter traditional pumping systems, but the presently disclosedsolid state pump 116 may be operable in well systems that are otherwiseinaccessible to more traditional artificial lift systems.

The solid state pump 116 may be conveyed downhole on a conveyance 120,which may comprise, but is not limited to, a wire, a cable, wireline,coiled tubing, drill pipe, slickline, or any combination thereof. In atleast one embodiment, the conveyance 120 may include a seven cablelogging cable that provides electrical communication with the surfacelocation 104 to provide telecommunication and electrical power downholeto operate the solid state pump 116. In such embodiments, the solidstate pump 116 may be powered by a surface power source 122 that maycomprise, but is not limited to, a generator (e.g., an AC generator, aDC generator, etc.), a genset, a turbine, solar-power, wind-power, oneor more batteries, one or more fuel cells, or any combination thereof.In other embodiments, however, the solid state pump 116 may be powereddownhole (locally) by an onboard power source 124 included in the solidstate pump 116. In such embodiments, the onboard power source 124 maycomprise, but is not limited to, a battery pack, one or more fuel cells,a downhole power generator, or any combination thereof. When batteriesare used in the surface or onboard power sources 122, 124, suchbatteries may be rechargeable.

In some embodiments, the solid state pump 116 may be conveyed downholewith the production tubing 112. In such embodiments, the solid statepump 116 may be installed within and otherwise coupled to the productiontubing 112 at the surface location 104 and extended into the wellbore106 concurrently with the production tubing 112. Moreover, in suchembodiments the solid state pump 116 may be referred to as a “tubingpump.”

In some embodiments, the well system 100 may further include a sealingassembly 126 configured to secure or seat the solid state pump 116within the production tubing 112 at a predetermined location (e.g., ator near the end of the production tubing 112). In some embodiments, thesealing assembly 126 may comprise a profile or radial shoulder definedon the inner radial surface of the production tubing 112 and configuredto receive a corresponding profile or outer radial shoulder provided bythe solid state pump 116. In other embodiments, the sealing assembly 126may comprise an expandable packer element that provides a sealedinterface between the production tubing 112 and the solid state pump116. In at least one embodiment, the radial sealing assembly 126 mayhelp isolate and otherwise separate the intake and discharge points ofthe solid state pump 116.

In example operation, the solid state pump 116 may be deployed downholeand at least partially immersed in wellbore liquids 127 present withinthe wellbore 106. The wellbore liquid 127 may include, but is notlimited to, water, condensate, liquid hydrocarbons, or any combinationthereof. Unless they are removed from the wellbore 106, the wellboreliquid 127 can obstruct gas production to the surface location 104.Accordingly, the solid state pump 116 may be configured to draw in andpressurize the wellbore liquid 127, and subsequently discharge apressurized wellbore liquid 128 into the production tubing 112 forproduction to the surface location 104. Wellbore gas 130 maysimultaneously be produced to the surface location 104 via an annulus132 defined between the production tubing 112 and the inner wall of thecasing 106.

In some embodiments, the well system 100 may include a control system134 configured to control operation of all or a portion of the wellsystem 100, such as the solid state pump 116. In some embodiments, thecontrol system 134 may be located at or adjacent the wellhead 102. Insuch embodiments, the control system 134 may include a display orterminal viewable by an operator to evaluate the status of the wellsystem 100. In other embodiments, however, the control system 134 may beremotely located and accessible by an operator via wired or wirelesscommunication. In yet other embodiments, the control system 134 may belocated downhole, such as forming part of the solid state pump 106. Insuch embodiments, the control system 134 may comprise an autonomous orautomatic controller programmed to control operation of the solid statepump 116 without requiring data or command signals sent from the surfacelocation 104.

The well system 100 may further include one or more sensors configuredto detect a variety of downhole parameters and communicate with thecontrol system 134. It is contemplated herein that one or more sensorsmay be present within the wellbore 106 at any suitable location. In atleast one embodiment, for example, a first sensor 136 a may beoperatively coupled to or form an integral part of the solid state pump116. The first sensor 136 a may be configured to detect processparameters relating to operation of the solid state pump 116 andcommunicate with the control system 134. When the control system 134 islocated at the surface location, the first sensor 136 a may communicatewith the control system 134 via the conveyance 120, but may otherwisecommunicate wirelessly with the control system 134. The control system134 may include computer hardware and a processor (e.g., microprocessor)configured to execute one or more sequences of instructions, programmingstances, or code stored on a non-transitory, computer-readable medium.Based on signals received from the first sensor 136 a, the controlsystem 134 may be configured to alter or control operation of the solidstate pump 116.

Moreover, in at least one embodiment, a second sensor 136 b may bepositioned at or near the surface location 104, such as at or near thewellhead 102. The second sensor 136 b may also be configured to monitordownhole parameters, but at or near the wellhead 102, and communicatedata and signals to the control system 134. While the second sensor 136b is depicted as being arranged outside the wellbore 106, it iscontemplated herein that the second sensor 136 b (or an additional thirdsensor) may be arranged within the wellbore 106 at or near the wellhead102, without departing from the scope of the disclosure.

The first and second sensors 136 a,b may comprise any suitableinstrument configured to detect one or more downhole parameters. Exampledownhole parameters include, but are not limited to, downholetemperature, downhole pressure, pressure and temperature at an inlet tothe solid state pump 116, inlet flow rate into the solid state pump 116,pressure and temperature at an outlet of the solid state pump 116, thetemperature of the solid state pump 116, internal pressure(s) of thesolid state pump 116, discharge flow rate from the solid state pump 116,system vibration, other pump system electrical/mechanicalcharacteristics, downhole flow rate, pressure and temperature at or nearthe wellhead 102, flowrate of gases or liquids out of the wellbore 106,or any combination thereof

Data obtained from the sensors 136 a,b allows the control system 134 toreport and/or display operating conditions of the well system 100 and,more particularly, the solid state pump 116. Based on data obtained bythe sensors 136 a,b, the control system 134 may be programmed tomaintain a target liquid level within the wellbore 106 above the solidstate pump 116. This may include increasing a discharge flow rate ofpressurized wellbore liquid 128 generated by the solid state pump 116 todecrease the liquid level within the wellbore 106 and/or decreasing thedischarge flow rate to increase the liquid level. In other embodiments,the control system 134 may be programmed to regulate the discharge flowrate to control the discharge pressure from the solid state pump 116 andthereby prevent deadheading against a closed valve at the wellhead 102.This may include increasing the discharge flow rate to increase thedischarge pressure and/or decreasing the discharge flow rate to decreasethe discharge pressure. In other embodiments, the control system 134 maybe programmed to shut off the solid state pump 116 when a certain systemparameter (such as temperature) exceeds or drops below a programmedwindow (threshold).

Unlike traditional rod pump systems, the solid state pump 116 mayoperate without utilizing a reciprocating mechanical linkage extendingto the surface location 104. This may allow the solid state pump 116 tobe utilized in long, deep, and/or deviated wellbores where traditionalrod pump systems may be ineffective, inefficient, or otherwise unable togenerate the pressurized wellbore liquid 128. Moreover, the solid statepump 116 may generate pressurized wellbore liquid 128 without requiringa threshold minimum pressure of wellbore gas 130. This may allow thesolid state pump 116 to be utilized in hydrocarbon wells that do notdevelop sufficient gas pressure to permit utilization of traditionalplunger lift systems.

Furthermore, the solid state pump 116 may operate as a positivedisplacement pump and thus may be sized, designed, and/or configured togenerate pressurized wellbore liquid 128 at a pressure that issufficient to convey the pressurized wellbore liquid 128 to the surfacelocation 104 without utilizing a large number of pumping stages.Reducing the number of pumping stages correspondingly decreases thelength of solid state pump 116. In some embodiments, for example, thesolid state pump 116 may include fewer than five stages or a singlestage.

FIG. 2 is an enlarged partial cross-sectional view of a portion of thewell system 100 of FIG. 1. FIG. 2 also depicts an enlarged schematicview of one example embodiment of the solid state pump 116. Asillustrated, the solid state pump 116 is positioned within theproduction tubing 112, and the production tubing 112 is extended withinthe casing 110. In the illustrated embodiment, the sealing assembly 126comprises an expandable packer used to receive and secure the solidstate pump 116 within the production tubing 112. The casing 110 includesa plurality of perforations 202 that provide fluid communication betweenthe wellbore 106 and the surrounding subterranean formation 108.

The solid state pump 116 may include a housing 204 and a solid stateactuator 206 may be positioned at least partially within the housing204. The housing 204 may at least partially define a pressure chamber208, and the solid state actuator 206 may be actuatable to extend atleast partially into the pressure chamber 208, as shown by the dashedlines. The housing 204 may provide or otherwise define one or more inletports 210 a (one shown) that places the pressure chamber 208 in fluidcommunication with the wellbore liquid 127 that may be present withinthe wellbore 106. The housing 204 may also provide or otherwise defineone or more outlet ports 210 b (two shown) that place the pressurechamber 208 in fluid communication with the interior of the productiontubing 112.

The solid state actuator 206 may include, but is not limited to apiezoelectric actuator, an electrostrictive actuator, amagnetorestrictive actuator, or any combination thereof. In someembodiments, the solid state actuator 206 may be made of a ceramicperovskite material, where the ceramic perovskite material may compriselead zirconate titanate or lead magnesium niobate. In other embodiments,the solid state actuator 206 may alternatively be made of terbiumdysprosium iron.

During an intake stroke of the solid state pump 116, the solid stateactuator 206 may selectively transition from an extended state (shown indashed lines) to a contracted state. In contrast, during an exhauststroke, the solid state actuator 206 may transition from the contractedstate to the extended state. During the intake stroke, the wellboreliquid 127 may be drawn into the pressure chamber 208 from the wellbore106 via the inlet port 210 a. In contrast, during the exhaust stroke,the pressurized wellbore liquid 128 may be discharged from the pressurechamber 208 via the outlet ports 210 b.

In some embodiments, actuating the solid state actuator 206 between theextended and contracted states may result from receipt of an electriccurrent, such as an AC (or DC) electric current. In such embodiments,the discharge flow rate of the pressurized wellbore liquid 128 generatedby the solid state pump 116 may be controlled, regulated, and/or variedby controlling, regulating, and/or varying the frequency of an AC (orDC) electric current provided to the solid state actuator 206. In someembodiments, the control system 134 (FIG. 1) may be programmed tocontrol the frequency of the AC (or DC) electric current provided to thesolid state actuator 206, thus controlling the discharge flow rate. Thismay include increasing the frequency of the AC (or DC) electric currentto increase the discharge flow rate and/or decreasing the frequency ofthe AC (or DC) electric current to decrease the discharge flow rate.

In some embodiments, the solid state actuator 206 may be configured tooperate at or near its resonant frequency. Illustrative, non-exclusiveexamples of the frequency of the AC (or DC) electric current includefrequencies of at least 0.01 Hertz (Hz), at least 0.05 Hz, at least 0.1Hz, at least 0.5 Hz, at least 1 Hz, at least 5 Hz, at least 10 Hz, atleast 20 Hz, at least 30 Hz, at least 40 Hz, at least 60 Hz, at least 80Hz, and/or at least 100 Hz. Additional illustrative, non-exclusiveexamples of the frequency of the AC (or DC) electric current includefrequencies of less than 4000 Hz, less than 3500 Hz, less than 3000 Hz,less than 2500 Hz, less than 2000 Hz, less than 1500 Hz, less than 1000Hz, less than 750 Hz, less than 500 Hz, less than 250 Hz, less than 200Hz, less than 150 Hz, and/or less than 100 Hz. Further illustrative,non-exclusive examples of the frequency of the AC (or DC) electriccurrent include frequencies in any range of the preceding minimum andmaximum frequencies.

The solid state pump 116 may include one or more check valves to helpregulate fluid flow through the pressure chamber 208 and therebyfacilitate the creation and pumping of the pressurized wellbore liquid128 from the wellbore 106 via the production tubing 112. Moreparticularly, one or more first check valves 214 a (one shown) may bearranged between the inlet port 210 a and the pressure chamber 208, andone or more second check valves 214 b (two shown) may be arrangedbetween the pressure chamber 208 and the outlet ports 210 b. The firstand second check valves 214 a,b may comprise any suitable structure thatallows fluid flow in one direction, but prevents the fluid from flowingin the opposite direction. Accordingly, the first check valve 214 a maypermit the wellbore liquid 127 to enter the pressure chamber 208, butresist, restrict, and/or block the pressurized wellbore liquid 128 fromreversing back into the wellbore 106. Moreover, the second check valves214 b may permit the pressurized wellbore liquid 128 to exit thepressure chamber 208 via the outlet ports 210 b, but resist, restrict,and/or block the pressurized wellbore liquid 128 from reversing backinto the pressure chamber 208.

In some embodiments, the first and second check valves 214 a,b may bepassive devices that are mechanically actuated based on fluid flow. Insuch embodiments, the first and second check valves 214 a,b may comprisepassive one-way disc valves. In other embodiments, however, the firstand second check valves 214 a,b may be active devices that areelectrically actuated and/or electrically controlled. In suchembodiments, the first and second check valves 214 a,b may comprise anytype of electrically controlled check valve such as, but not limited to,an active microvalve array, an active micro electromechanical system(MEMS) valve array or a combination thereof. The control system 134(FIG. 1) may be in communication with the first and second check valves214 a,b to control operation thereof. As the first and second checkvalves 214 a,b operate, the wellbore gas 130 may flow within the annulus132 defined between the casing 110 and the production tubing 112.

In the illustrated embodiment, the first sensor 136 a is arranged at ornear the inlet port 210 a to detect a plurality of downhole parametersat that location. A third sensor 136 c may be arranged at or near theoutlet ports 210 b to likewise detect downhole parameters at thatlocation. Data obtained by the first and third sensors 136 a,c may becommunicated to the control system 134 (FIG. 1) to help regulateoperation of the solid state pump 116.

FIG. 3 is an enlarged schematic view of another example embodiment ofthe solid state pump 116 that may be used in the well system 100. Likenumerals used in both FIG. 2 and FIG. 3 refer to like components notdescribed again. As illustrated, the solid state pump 116 is extendedinto the production tubing 112 on the conveyance 120, and the productiontubing 112 is extended within the casing 110. In the illustratedembodiment, the sealing assembly 126 comprises a profile seat 302positioned within the production tubing 112 and configured to engage acorresponding radial extension 304 coupled to or forming part of thesolid state pump 116. In some embodiments, the profile seat 302 maycomprise a locking groove structured and arranged to matingly engage theradial extension 304.

The solid state actuator 206 may be positioned within the housing 204and actuatable to draw the wellbore liquid 127 into the pressure chamber208, and discharge pressurized wellbore liquid 128. The inlet port 210 ais provided on the housing 204 to place the pressure chamber 208 influid communication with the wellbore liquid 127, and the outlet ports210 b (one shown) are provided on the housing 204 to place the pressurechamber 208 in fluid communication with the interior of the productiontubing 112. The first check valve 214 a is arranged between the inletport 210 a and the pressure chamber 208, and the second check valves 214b (one shown) are arranged between the pressure chamber 208 and theoutlet ports 210 b.

In some embodiments, the solid state pump 116 may include a barrier 306configured to isolate the solid state actuator 206 from the pressurechamber 208 and thereby isolate the wellbore liquid 127 from the solidstate actuator 206. This may prove advantageous in preventing wellboreliquids containing particulates from directly contacting the solid stateactuator 206. In some embodiments, the barrier 306 may comprise a pistonmovable into and out of the pressure chamber 208 based on actuation ofthe solid state actuator 206. In such embodiments, the solid state pump116 may be characterized as a piston pump or the like. In otherembodiments, however, the barrier 306 may comprise a flexible isolationstructure that is movable into and out of the pressure chamber 208 basedon actuation of the solid state actuator 206. In such embodiments, theflexible isolation structure may comprise, for example, a diaphragm, anisolation coating, or a combination thereof, and the solid state pump116 may be characterized as a diaphragm pump. In yet other embodiments,the barrier 306 may comprise a sealing structure, such as an O-ring orthe like.

In some embodiments, the system 100 may further include a well screen orfilter 308 in fluid communication with the inlet port 210 a of the solidstate pump 116. As illustrated, the filter 308 may include a screen 310through which the wellbore liquid 127 may pass, but sand and debris(e.g., fluid particulates) of a predetermined size may be prevented frompassing therethrough. Accordingly, the screen 310 may operate as a sandscreen. Moreover, however, the screen 310 may also be configured torestrict flow of the wellbore gas 130 therethrough and into the solidstate pump 116.

In at least one embodiment, the filter 308 may further include astanding valve 312 designed to allow the wellbore liquid 127 to passuphole, but prevent the wellbore liquid 127 from reversing back into thewellbore 106 below the filter 308. Accordingly, the standing valve 312may operate as a one-way check valve. In at least one embodiment, thestanding valve 312 may comprise a velocity fuse structured and arrangedto back-flush the filter 308 and maintain a column of fluid within theproduction tubing 112 in response to an increase in pressure drop acrossthe filter 308.

FIG. 4 is a schematic diagram of an example positive-displacement solidstate pump 402, according to embodiments of the present disclosure. Thepositive-displacement solid state pump 402 (hereafter “the solid statepump 402”) may be the same as or similar to the solid state pump 116 ofFIGS. 1-3 and, therefore, may be best understood therewith. In someembodiments, the solid state pump 402 may replace the solid state pump116 (or any other solid state pump described herein) in any of theembodiments discussed herein.

As illustrated, the solid state pump 402 may include a housing 404 and asolid state actuator 406 may be positioned at least partially within thehousing 404. The solid state actuator 406 may be similar to the solidstate actuator 206 of FIGS. 2-3 and, in the illustrated embodiment, maycomprise a piezoelectric actuator stack. A power source 408 may becommunicably coupled to the solid state actuator 406 to provide powerthereto, such as AC (or DC) current. In some embodiments, the powersource 408 may comprise a surface power source, such as the surfacepower source 122 of FIG. 1. In other embodiments, however, the powersource 408 may comprise a downhole power source, such as the onboardpower source 124 of FIG. 1, without departing from the scope of thedisclosure. In either scenario, the power source 408 may be incommunication with the control system 134 (FIG. 1), which may controloperation of the solid state pump 402. A frequency modulator 410 and anamplitude modulator 412 may be connected in series, and can be adjustedto vary the frequency and amplitude of the signal conveyed to the solidstate actuator 406.

The housing 404 may at least partially define a pressure chamber 414 anda barrier 416 may be arranged to isolate the solid state actuator 406from the pressure chamber 414. In the illustrated embodiment, thebarrier 416 comprises a flexible diaphragm, but could alternativelycomprise any of the other example barriers mentioned herein. The housing404 may also provide or otherwise define an inlet port 418 a and anoutlet port 418 b. A first check valve 420 a interposes the inlet port418 a and the pressure chamber 414 and controls fluid flow into thepressure chamber 414. Similarly, a second check valve 420 b interposesthe outlet port 418 b and the pressure chamber 414 and controls fluidflow out of the pressure chamber 414.

Similar to the first and second check valves 214 a,b of FIGS. 2-3, thefirst and second check valves 420 a,b may be passive or active devices.More specifically, the first and second check valves 420 a,b may bemechanically actuated based on fluid flow or may be electricallyactuated and/or electrically controlled. In embodiments where the firstand second check valves 420 a,b are mechanically actuated (passive), thefirst and second check valves 420 a,b may comprise passive one-way discvalves. In embodiments where the first and second check valves 420 a,bare electrically controlled (active), the first and second check valves420 a,b may be communicably coupled to the power source 408 and thecontrol system 134 to power and operate (e.g., open or close) the firstand second check valves 420 a,b. Moreover, in such embodiments, thefirst and second check valves 420 a,b may comprise any type ofelectrically controlled check valve such as, but not limited to, anactive microvalve array, an active micro electromechanical system (MEMS)valve array or a combination thereof

Referring now to FIGS. 5A and 5B, with continued reference to FIG. 4,example operation of the solid state pump 402 is depicted, according toone or more embodiments. As voltage (or current) is applied to the solidstate actuator 406 via the power source 408 (FIG. 4), the solid stateactuator 406 will expand and contract in response to the suppliedsignal, which causes the barrier 416 to flex (bend) up and down in apiston-like fashion.

In FIG. 5A, when the barrier 416 flexes downward, the pressure chamber414 experiences a pressure drop, which causes the first check valve 420a to open and permit the flow of fluid into the pressure chamber 414.The pressure drop correspondingly urges the second check valve 420 b toclose and thereby prevent a back flow of fluid from the outlet port 418b into the pressure chamber 414. In embodiments where the first andsecond check valves 420 a,b are electrically controlled, however, thecontrol system 134 may operate (open and close) the first and secondcheck valves 420 a,b based on a predetermined operational program orotherwise based on detected pressures within the pressure chamber 414.

In FIG. 5B, when the barrier 416 flexes upward, the pressure chamber 414experiences an increase in pressure, which causes the second check valve420 b to open and permit fluid flow out of the pressure chamber 414. Thepressure increase correspondingly urges the first check valve 420 a toclose and thereby prevent a back flow of fluid from the pressure chamber414 into the inlet port 418 a. In embodiments where the first and secondcheck valves 420 a,b are electrically controlled, the control system 134may operate (open and close) the first and second check valves 420 a,bbased on a predetermined operational program or otherwise based ondetected pressures within the pressure chamber 414. This process may berepeated to enable to solid state pump 402 to continuously pump fluidfrom the inlet port 418 a to the outlet port 418 b.

FIG. 6 is an enlarged schematic view of another example pump 602 thatmay be used in the well system 100 of FIG. 1, according to one or moreembodiments of the present disclosure. The pump 602 may be similar insome respects to the pump 116 of FIGS. 1-3 and thus may be bestunderstood with reference thereto. In some embodiments, the pump 602 mayreplace the pump 116. Accordingly, the pump 602 may be conveyed into thewellbore 106 via the conveyance 120, and the pump 602 may becommunicably coupled to the control system 134, which may control thepump 602. The control system 134 may be arranged either at the surfacelocation 104 (FIG. 1) or otherwise included in the pump 602.

As illustrated, the pump 602 may include a housing 604 that contains orotherwise houses a first pump 606 and a second pump 608. In at least oneembodiment, however, at least one of the pumps 606, 608 may bepositioned outside of the housing 604, such as forming part of anotherdownhole tool or component operatively coupled to the housing 604 or theconveyance 120. The first pump 606 may comprise a positive-displacementsolid state pump, similar to or the same as the solid state pump 116 ofFIGS. 1-3 or the solid state pump 402 of FIGS. 4 and 5A-5B. Accordingly,the first pump 606 may be referred to herein as the solid state pump606, and may include a solid state actuator 611 actuatable to extend atleast partially into a pressure chamber 612 defined in the housing 604,as shown by the dashed lines. The solid state actuator 611 may be thesame as or similar to the solid state actuators 206 and 406 discussedherein, and thus may include, but is not limited to a piezoelectricactuator, an electrostrictive actuator, a magnetorestrictive actuator,or any combination thereof

The solid state pump 606 may be in fluid communication with the secondor “secondary” pump 608 via a fluid circuit 610. In some embodiments, asillustrated, the fluid circuit 610 may be arranged or otherwisecontained within the housing 604. In other embodiments, however, aportion of the fluid circuit 610 may be positioned external to thehousing 604. As described herein, the solid state pump 606 and thesecondary pump 608 may cooperatively operate to draw the wellbore liquid127 into the pump 602, pressurize the wellbore liquid 127, and dischargethe pressurized wellbore liquid 128 from the pump 602 into theproduction tubing 112 for production to the surface location 104 (FIG.1). In at least one embodiment, the solid state pump 606 may operate asthe “power end” to the pump 602, while the secondary pump 608 mayoperate as the “fluid end” to the pump 602.

In the illustrated embodiment, the secondary pump 608 comprises one ormore expansion pumps, shown as a first expansion pump 614 a and a secondexpansion pump 614 b. While two expansion pumps 614 a,b are depicted, itis contemplated herein that a single expansion pump (or more than two)may be employed, without departing from the scope of the disclosure.

In the illustrated embodiment, the expansion pumps 614 a,b areconfigured to operate in parallel within the fluid circuit 610. Eachexpansion pump 614 a,b includes an expandable member 616 positionedwithin a corresponding expansion tank 618. In some embodiments, theexpandable member 616 may comprise an elastomer bladder, but in otherembodiments, the expandable member 616 may comprise a metal bellows. Inyet other embodiments, the expandable member 616 may comprise acombination of an elastomer bladder and a metal bellows.

In some embodiments, the housing 604 may provide or otherwise define oneor more inlet ports, shown as a first inlet port 620 a and a secondinlet port 620 b. The first expansion pump 614 a may be in fluidcommunication with the wellbore liquid 127 via the first inlet port 620a, and the second expansion pump 614 b may be in fluid communicationwith the wellbore liquid 127 via the second inlet port 620 b. In theillustrated embodiment, the expansion tanks 618 of the first and secondexpansion pumps 614 a,b are fluidly coupled to the first and secondinlet ports 620 a,b, respectively. In other embodiments, however, theexpandable member 616 of the first and second expansion pumps 614 a,bmay alternatively be fluidly coupled to the first and second inlet ports620 a,b, respectively, without departing from the scope of thedisclosure.

In some embodiments, the housing 604 may further provide or otherwisedefine one or more outlet ports, shown as a first outlet port 622 a, anda second outlet port 622 b. The first expansion pump 614 a may be influid communication with the interior of the production tubing 112 viathe first outlet port 622 a, and the second expansion pump 614 b may bein fluid communication with the interior of the production tubing 112via the second outlet port 622 b. In the illustrated embodiment, theexpansion tanks 618 of the first and second expansion pumps 614 a,b arefluidly coupled to the first and second outlet ports 622 a,b,respectively. In other embodiments, however, the expandable members 616of the first and second expansion pumps 614 a,b may alternatively befluidly coupled to the first and second outlet ports 622 a,b,respectively, without departing from the scope of the disclosure.

While the inlet ports 620 a,b and the outlet ports 622 a,b are eachdepicted as being provided or otherwise defined by the housing 604, itis contemplated herein that some or all of the inlet ports 620 a,b andthe outlet ports 622 a,b may be provided or otherwise defined by anotherdownhole tool or component operatively coupled to the housing 604 or theconveyance 120.

Actuation of the expansion pumps 614 a,b may cause the wellbore liquid127 to be drawn into the pump 602 and subsequently discharged aspressurized wellbore liquid 128 into the production tubing 112. Theexpansion pumps 614 a,b may be actuated by repeatedly expanding andcontracting the expandable member 616 of each expansion pump 614 a,b. Inthe illustrated embodiment, actuation of the expansion pumps 614 a,bcauses the wellbore liquid 127 to be drawn into the respective expansiontank 618 and subsequently discharged as pressurized wellbore liquid 128.In other embodiments, however, actuating the expansion pumps 614 a,b maydraw the wellbore liquid 127 into the respective expandable member 616,which may subsequently discharge the pressurized wellbore liquid 128.

In the illustrated embodiment, the expandable members 616 may beactuated (expanded and contracted) by circulating a hydraulic fluidthrough the fluid circuit 610 and, more particularly, through eachexpandable member 616. In other embodiments, however, the expandablemembers 616 may be actuated (expanded and contracted) by circulating ahydraulic fluid through the respective expansion chambers 618. In suchembodiments, the circulating hydraulic fluid within the expansionchambers 618 acts on and causes the expandable members 616 to expand andcontract. The hydraulic fluid may be made of, but is not limited to, amineral oil, a dielectric oil, water, a fluid with specific additives topromote system reliability, or any combination thereof.

The solid state pump 606 may be operable to circulate the hydraulicfluid through the fluid circuit 610, and thereby actuate the expansionpumps 614 a,b. More particularly, the solid state pump 606 may includean inlet 624 a that receives the hydraulic fluid into the pressurechamber 612, and an outlet 624 b that discharges pressurized hydraulicfluid from the pressure chamber 612. Actuating the solid state actuator611 may draw the hydraulic fluid into the pressure chamber 612 andsubsequently discharge the pressurized hydraulic fluid toward theexpansion pumps 614 a,b. In some embodiments, the fluid circuit 610 maybe a closed loop system, which may prove advantageous in mitigatingdamage to the solid state pump 606 that might ensue from circulating afluid with foreign particulate matter (e.g., the wellbore liquid 127)therethrough.

In some embodiments, the pump 602 may further include a switching valve626 arranged in the fluid circuit 610 and interposing the solid statepump 606 and the secondary pump 608. The switching valve 626 may beconfigured to coordinate hydraulic fluid flow within the fluid circuit610 and, more particularly, between the first and second expansion pumps614 a,b as needed. In some embodiments, the switching valve 626 may becommunicably coupled to the control system 134, which may be programmedto operate the switching valve 626.

In example operation, the switching valve 626 may be in a first statewhere hydraulic fluid flow is provided to actuate the first expansionpump 614 a and thereby discharge pressurized wellbore liquid 128 via thefirst outlet 622 a. In the illustrated embodiment, the hydraulic fluidmay be conveyed into the expandable member 616 of the first expansionpump 614 a, which progressively compresses the wellbore liquid 127present within the expansion tank 618 and eventually urges thepressurized wellbore liquid 128 out of the expansion tank 618. In otherembodiments, however, the hydraulic fluid may alternatively be conveyedinto the expansion tank 618 of the first expansion pump 614 a, whichprogressively acts on the wellbore liquid 127 that may be present withinthe expandable member 616 and eventually urges the pressurized wellboreliquid 128 out of the expandable member 616.

With the switching valve 626 in the first state, hydraulic fluid may bealso be received from the second expansion pump 614 b. Morespecifically, in the illustrated embodiment, as the expandable member616 of the second expansion pump 614 b contracts toward its naturalstate, hydraulic fluid within the expandable member 616 may be conveyedto the switching valve 626, which conveys the hydraulic fluid to thepressure chamber 612 to be pressurized. As the expandable member 616contracts, additional wellbore liquid 127 may be drawn into theexpansion chamber 618 of the second expansion pump 614 b.

The switching valve 626 may then be actuated or “switched” to a secondstate where hydraulic fluid flow is provided to actuate the secondexpansion pump 614 b and thereby discharge pressurized wellbore liquid128 via the second outlet 622 b. In the illustrated embodiment, thehydraulic fluid may be conveyed into the expandable member 616 of thesecond expansion pump 614 b, which progressively compresses the wellboreliquid 127 present within the expansion tank 618 and eventually urgesthe pressurized wellbore liquid 128 out of the expansion tank 618. Inother embodiments, however, the hydraulic fluid may alternatively beconveyed into the expansion tank 618 of the second expansion pump 614 b,which progressively acts on the wellbore liquid 127 that may be presentwithin the expandable member 616 and eventually urges the pressurizedwellbore liquid 128 out of the expandable member 616.

With the switching valve 626 in the second state, hydraulic fluid may bealso be received from the first expansion pump 614 a. More specifically,in the illustrated embodiment, as the expandable member 616 of the firstexpansion pump 614 a contracts toward its natural state, hydraulic fluidwithin the expandable member 616 may be conveyed to the switching valve626, which conveys the hydraulic fluid to the pressure chamber 612 to bepressurized. As the expandable member 616 contracts, additional wellboreliquid 127 may be drawn into the expansion chamber 618 of the firstexpansion pump 614 a.

The switching valve 626 may be repeatedly operated as described above tocontinuously discharge the pressurized wellbore liquid 128 into theproduction tubing 112 for production to the surface location 104 (FIG.1).

One or more check valves may be included in the pump 602 to helpregulate fluid flow through each expansion pump 614 a,b and thereby helpfacilitate the creation and pumping of the pressurized wellbore liquid128. More particularly, one or more first check valves 628 a may bearranged between the first and second inlet ports 620 a,b and theexpansion pumps 614 a,b, respectively, and one or more second checkvalves 628 b may be arranged between each expansion pump 614 a,b and thefirst and second outlet ports 622 a,b, respectively. The first andsecond check valves 628 a,b may be passive or active devices similar tothe first and second check valves 214 a,b of FIGS. 2 and 3, and,therefore, may comprise any suitable structure that allows fluid flow inone direction, but prevents the fluid from flowing in the oppositedirection. The first check valves 628 a may permit the wellbore liquid127 to enter each expansion pump 614 a,b, but resist, restrict, and/orblock the wellbore liquid 127 from reversing back into the wellbore 106.Moreover, the second check valves 628 b may permit the pressurizedwellbore liquid 128 to exit each expansion pump 614 a,b, but resist,restrict, and/or block the pressurized wellbore liquid 128 fromreversing back into the respective expansion pump 614 a,b.

Moreover, one or more additional check valves 630 may be included in thefluid circuit 610 to help regulate hydraulic fluid flow between thesolid state pump 606 and the secondary pump 608 and through theswitching valve 626. As illustrated, one or more check valves 630 mayinterpose the pressure chamber 612 and the switching valve 626. One ormore check valves 630 may also interpose the switching valve 626 andeach expansion pump 614 a,b. The check valves 630 may be passive oractive devices that help regulate hydraulic fluid flow through thehydraulic circuit 610. In some embodiments, some or all of the checkvalves 630 may comprise electrically controlled check valves incommunication with the control system 134. In such embodiments, thecontrol system 134 may operate the check valves 630 to ensure properfluid flow to generate the pressurized wellbore liquid 128.

In some embodiments, the pump 602 may further include one or moresensors used to monitor operation of the secondary pump 608. In theillustrated embodiment, for example, a first sensor 632 a may beincluded in or otherwise associated with the first expansion pump 614 a,and a second sensor 632 b may be included in or otherwise associatedwith the second expansion pump 614 b. In some embodiments, the first andsecond sensors 632 a,b may be in communication with the control system134 and used to determine when an expandable member 616 has reached anexpansion/contraction limit and thereby help trigger a change in theflow path of the pumped hydraulic fluid so that the other expandablemember 616 might be filled/emptied. The sensors 632 a,b may comprisemechanical and/or electrical sensors such as, but not limited to, aposition sensor, a volumetric sensor, a pressure sensor, a tensilesensor, or any combination thereof. In at least one embodiment, outputsfrom the sensors 632 a,b may be conveyed to the control system 134 totrigger actuation of the switching valve 626 and thereby alter thehydraulic fluid flow path. Alternatively, the switching valve 626 may beactuated based on a pre-programmed timer that determines switchactivation and frequency.

FIG. 7 is an enlarged schematic view of another example pump 702 thatmay be used in the well system 100 of FIG. 1, according to one or moreembodiments of the present disclosure. The pump 702 may be similar insome respects to the pump 602 of FIG. 6 and therefore may be bestunderstood with reference thereto, where like numerals will representlike components not described again in detail. Similar to the pump 602of FIG. 6, the pump 702 may replace the pump 116 of FIGS. 1-3.Accordingly, the pump 702 may be conveyed into the wellbore 106 via theconveyance 120, and the pump 702 may be communicably coupled to thecontrol system 134, which may control operation of the pump 702. Thecontrol system 134 may be arranged either at the surface location 104(FIG. 1) or otherwise included in the pump 702.

As illustrated, the pump 702 includes the solid state pump 606positioned within the housing 604. The pump 702 further includes asecondary pump 704 that may also be positioned within the housing 604 oralternatively form part of another downhole tool or componentoperatively coupled to the housing 604 or the conveyance 120. The solidstate pump 606 may be in fluid communication with the secondary pump 704via a fluid circuit 706. In some embodiments, as illustrated, the fluidcircuit 706 may be arranged or otherwise contained within the housing604. In other embodiments, however, a portion of the fluid circuit 706may be positioned external to the housing 604.

The solid state pump 606 and the secondary pump 704 may cooperativelyoperate to draw the wellbore liquid 127 into the pump 702, pressurizethe wellbore liquid 127, and discharge the pressurized wellbore liquid128 from the pump 702 into the production tubing 112 for production tothe surface location 104 (FIG. 1). In at least one embodiment, the solidstate pump 606 may operate as the “power end” to the pump 702, while thesecondary pump 704 may operate as the “fluid end” to the pump 702.

In the illustrated embodiment, the secondary pump 704 comprises ahydraulic motor 708 operatively coupled to a fluid pump 710 with a driveshaft 712. The hydraulic motor 708 may be configured to converthydraulic pressure and flow into torque and angular displacement(rotation) of the drive shaft 712, which causes actuation of the fluidpump 710. The fluid pump 710 may comprise any type of pump configured topressurize and discharge a pressurized fluid. The fluid pump 710 mayinclude, but is not limited to, a centrifugal pump, a rotary screw pump,a rotary lobe pump, a gerotor pump, a progressive cavity pump, or anycombination thereof.

In some embodiments, the housing 604 may provide or otherwise define oneor more inlet ports 714 (one shown). The fluid pump 710 may be in fluidcommunication with the wellbore liquid 127 via the inlet port 714. Thehousing 604 may further provide or otherwise define one or more outletports 716 (two shown). The fluid pump 710 may be in fluid communicationwith the interior of the production tubing 112 via the outlet ports 716.While the inlet and outlet ports 714, 716 are depicted as being providedor otherwise defined by the housing 604, it is contemplated herein thatsome or all of the inlet and outlet ports 714, 716 may be provided orotherwise defined by another downhole tool or component operativelycoupled to the housing 604 or the conveyance 120.

Actuation of the fluid pump 710 may cause the wellbore liquid 127 to bedrawn into the pump 702 and subsequently discharged as pressurizedwellbore liquid 128 into the production tubing 112. The fluid pump 710may be actuated by rotating the drive shaft 712, and actuating the fluidpump 710 causes the wellbore liquid 127 to be drawn into the fluid pump710 and subsequently discharged as pressurized wellbore liquid 128. Thedrive shaft 712 may be rotated by circulating a hydraulic fluid throughthe fluid circuit 706 and, more particularly, through the hydraulicmotor 708. As with the embodiment of FIG. 6, the hydraulic fluid may bemade of, but is not limited to, a mineral oil, a dielectric oil, water,or any combination thereof.

The solid state pump 606 may be operable to circulate the hydraulicfluid through the fluid circuit 706, and thereby actuate the hydraulicmotor 708. More particularly, actuating the solid state actuator 611 maydraw the hydraulic fluid into the pressure chamber 612 via the inlet 624a and subsequently discharge the pressurized hydraulic fluid toward thehydraulic motor 708 via the outlet 624 b. Accordingly, the pump 702 maybe configured to convert the reciprocating motion of the solid stateactuator 611 into a rotating motion of the drive shaft 712 at thehydraulic pump 708, which drives (actuates) the fluid pump 710.

One or more check valves may be included in the pump 702 to helpregulate fluid flow through the fluid pump 710 and thereby helpfacilitate the creation and pumping of the pressurized wellbore liquid128. More particularly, one or more first check valves 718 a (one shown)may be arranged between the inlet port 714 and the fluid pump 710, andone or more second check valves 718 b (two shown) may be arrangedbetween the fluid pump 710 and the outlet ports 716. The first andsecond check valves 718 a,b may be passive or active devices similar tothe first and second check valves 214 a,b of FIGS. 2 and 3, and,therefore, may comprise any suitable structure that allows fluid flow inone direction, but prevents the fluid from flowing in the oppositedirection. The first check valve 718 a may permit the wellbore liquid127 to the fluid pump 710, but resist, restrict, and/or block thewellbore liquid 127 from reversing back into the wellbore 106. Moreover,the second check valves 718 b may permit the pressurized wellbore liquid128 to exit the fluid pump 710, but resist, restrict, and/or block thepressurized wellbore liquid 128 from reversing back into the fluid pump710.

Moreover, one or more additional check valves 720 may be included in thefluid circuit 706 to help regulate hydraulic fluid flow between thesolid state pump 606 and the secondary pump 704. As illustrated, one ormore check valves 720 may interpose the pressure chamber 612 and thehydraulic pump 708. The check valves 720 may be passive or activedevices that help regulate hydraulic fluid flow through the hydrauliccircuit 706. In some embodiments, some or all of the check valves 720may be electrically controlled and in communication with the controlsystem 134. In such embodiments, the control system 134 may operate thecheck valves 720 to ensure proper fluid flow to generate the pressurizedwellbore liquid 128.

Consistent with any of the embodiments described herein, it iscontemplated to include multiple pumps (e.g., solid state pump)installed in the well system 100, without departing from the scope ofthe disclosure. As will be appreciated, this would increase the maximumvolume flow possible. Each independent pump would need to have anindependent inlet, but their outlets may be combined to reduce the totalnumber of flow conduits necessary.

Embodiments disclosed herein include:

A. A pump that includes a solid state pump including a solid stateactuator actuatable to pressurize a hydraulic fluid, and a secondarypump in fluid communication with the solid state pump via a fluidcircuit, wherein the secondary pump is actuatable with the hydraulicfluid received from the solid state pump, and wherein actuating thesecondary pump draws in an external fluid into the secondary pump,pressurizes the external fluid within the secondary pump, and dischargesa pressurized external fluid.

B. A well system that includes a pump arrangeable within productiontubing extended within a wellbore, the pump including a solid state pumpincluding a solid state actuator actuatable to pressurize a hydraulicfluid, and a secondary pump in fluid communication with the solid statepump via a fluid circuit, wherein the secondary pump is actuatable withthe hydraulic fluid received from the solid state pump. The well systemfurther including a control system communicably coupled to the pump tocontrol operation of the pump, wherein actuating the secondary pumpdraws a wellbore liquid into the secondary pump, pressurizes thewellbore liquid within the secondary pump, and discharges a pressurizedwellbore liquid into the production tubing for production to a surfacelocation.

C. A method that includes positioning a pump within production tubingextended within a wellbore, the pump including a solid state pump havinga solid state actuator, and a secondary pump in fluid communication withthe solid state pump via a fluid circuit, actuating the solid stateactuator and thereby conveying a hydraulic fluid to the secondary pumpvia the fluid circuit, actuating the secondary pump with the hydraulicfluid received from the solid state pump and thereby drawing a wellboreliquid into the secondary pump and pressurizing the wellbore liquidwithin the secondary pump, discharging a pressurized wellbore liquidfrom the secondary pump and into the production tubing for production toa surface location, and controlling operation of the pump with a controlsystem communicably coupled to the pump.

Each of embodiments A, B, and C may have one or more of the followingadditional elements in any combination: Element 1: wherein the solidstate actuator is selected from the group consisting of a piezoelectricactuator, an electrostrictive actuator, a magnetorestrictive actuator,and any combination thereof. Element 2: further comprising one or morecheck valves that control flow of the hydraulic fluid and the externalfluid. Element 3: wherein the secondary pump comprises one or moreexpansion pumps, and each expansion pump includes an expansion tank andan expandable member positioned within the expansion tank. Element 4:wherein the expandable member comprises at least one of an elastomerbladder and a metal bellows. Element 5: wherein the one or moreexpansion pumps comprise a first expansion pump and a second expansionpump, and wherein the pump further comprises a switching valve arrangedin the fluid circuit to coordinate hydraulic fluid flow between thesolid state pump and the first and second expansion pumps. Element 6:wherein the secondary pump comprises a hydraulic motor in fluidcommunication with the solid state pump to receive the hydraulic fluidand thereby rotate a drive shaft, and a fluid pump operatively coupledto the hydraulic motor via the drive shaft, wherein the external fluidis drawn into the fluid pump and pressurized upon rotating the driveshaft. Element 7: wherein the fluid pump is selected from the groupconsisting of a centrifugal pump, a rotary screw pump, a rotary lobepump, a gerotor pump, a progressive cavity pump, and any combinationthereof.

Element 8: further comprising one or more sensors in communication withthe control system and operable to detect one or more downholeparameters, wherein operation of the pump is based on one or moresignals received from the one or more sensors. Element 9: wherein thesolid state actuator is selected from the group consisting of apiezoelectric actuator, an electrostrictive actuator, amagnetorestrictive actuator, and any combination thereof. Element 10:wherein the secondary pump comprises one or more expansion pumps, andeach expansion pump includes an expansion tank and an expandable memberpositioned within the expansion tank. Element 11: wherein the expandablemember comprises at least one of an elastomer bladder and a metalbellows. Element 12: wherein the one or more expansion pumps comprise afirst expansion pump and a second expansion pump, the well systemfurther comprising a switching valve arranged in the fluid circuit tocoordinate hydraulic fluid flow between the solid state pump and thefirst and second expansion pumps. Element 13: wherein the secondary pumpcomprises a hydraulic motor in fluid communication with the solid statepump to receive the hydraulic fluid and thereby rotate a drive shaft,and a fluid pump operatively coupled to the hydraulic motor via thedrive shaft, wherein the wellbore liquid is drawn into the fluid pumpand pressurized upon rotation of the drive shaft. Element 14: whereinthe fluid pump comprises a pump selected from the group consisting of acentrifugal pump, a rotary screw pump, a rotary lobe pump, a gerotorpump, a progressive cavity pump, and any combination thereof.

Element 15: further comprising detecting one or more downhole parameterswith one or more sensors in communication with the control system, andcontrolling operation of the pump based at least partially on one ormore signals received from the one or more sensors. Element 16: whereinthe secondary pump comprises a first expansion pump and a secondexpansion pump, and wherein a switching valve is arranged in the fluidcircuit, the method further comprising operating the switching valve tocoordinate hydraulic fluid flow between the solid state pump and thefirst and second expansion pumps. Element 17: wherein the secondary pumpcomprises a hydraulic motor in fluid communication with the solid statepump, and a fluid pump operatively coupled to the hydraulic motor at adrive shaft extended from the hydraulic motor, the method furthercomprising receiving the hydraulic fluid from the solid state pump atthe hydraulic motor and thereby rotating the drive shaft, and drawingthe wellbore liquid into the fluid pump upon rotation of the driveshaft, and thereby pressurizing the wellbore liquid.

By way of non-limiting example, exemplary combinations applicable to A,B, and C include: Element 3 with Element 4; Element 3 with Element 5;Element 6 with Element 7; Element 10 with Element 11; Element 10 withElement 12; and Element 13 with Element 14.

Therefore, the disclosed systems and methods are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as the teachings of the present disclosure may be modified andpracticed in different but equivalent manners apparent to those skilledin the art having the benefit of the teachings herein. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered, combined, or modified and all such variations are consideredwithin the scope of the present disclosure. The systems and methodsillustratively disclosed herein may suitably be practiced in the absenceof any element that is not specifically disclosed herein and/or anyoptional element disclosed herein. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementsthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

As used herein, the phrase “at least one of” preceding a series ofitems, with the terms “and” or “or” to separate any of the items,modifies the list as a whole, rather than each member of the list (i.e.,each item). The phrase “at least one of” allows a meaning that includesat least one of any one of the items, and/or at least one of anycombination of the items, and/or at least one of each of the items. Byway of example, the phrases “at least one of A, B, and C” or “at leastone of A, B, or C” each refer to only A, only B, or only C; anycombination of A, to B, and C; and/or at least one of each of A, B, andC.

The use of directional terms such as above, below, upper, lower, upward,downward, left, right, uphole, downhole and the like are used inrelation to the illustrative embodiments as they are depicted in thefigures, the upward direction being toward the top of the correspondingfigure and the downward direction being toward the bottom of thecorresponding figure, the uphole direction being toward the surface ofthe well and the downhole direction being toward the toe of the well.

What is claimed is:
 1. A pump, comprising a solid state pump including asolid state actuator actuatable to pressurize a hydraulic fluid; and asecondary pump in fluid communication with the solid state pump via afluid circuit, wherein the secondary pump is actuatable with thehydraulic fluid received from the solid state pump, and whereinactuating the secondary pump draws in an external fluid into thesecondary pump, pressurizes the external fluid within the secondarypump, and discharges a pressurized external fluid.
 2. The pump of claim1, wherein the solid state actuator is selected from the groupconsisting of a piezoelectric actuator, an electrostrictive actuator, amagnetorestrictive actuator, and any combination thereof.
 3. The pump ofclaim 1, further comprising one or more check valves that control flowof the hydraulic fluid and the external fluid.
 4. The pump of claim 1,wherein the secondary pump comprises one or more expansion pumps, andeach expansion pump includes an expansion tank and an expandable memberpositioned within the expansion tank.
 5. The pump of claim 4, whereinthe expandable member comprises at least one of an elastomer bladder anda metal bellows.
 6. The pump of claim 4, wherein the one or moreexpansion pumps comprise a first expansion pump and a second expansionpump, and wherein the pump further comprises a switching valve arrangedin the fluid circuit to coordinate hydraulic fluid flow between thesolid state pump and the first and second expansion pumps.
 7. The pumpof claim 1, wherein the secondary pump comprises: a hydraulic motor influid communication with the solid state pump to receive the hydraulicfluid and thereby rotate a drive shaft; and a fluid pump operativelycoupled to the hydraulic motor via the drive shaft, wherein the externalfluid is drawn into the fluid pump and pressurized upon rotating thedrive shaft.
 8. The pump of claim 7, wherein the fluid pump is selectedfrom the group consisting of a centrifugal pump, a rotary screw pump, arotary lobe pump, a gerotor pump, a progressive cavity pump, and anycombination thereof.
 9. A well system, comprising: a pump arrangeablewithin production tubing extended within a wellbore, the pump including:a solid state pump including a solid state actuator actuatable topressurize a hydraulic fluid; and a secondary pump in fluidcommunication with the solid state pump via a fluid circuit, wherein thesecondary pump is actuatable with the hydraulic fluid received from thesolid state pump; and a control system communicably coupled to the pumpto control operation of the pump, wherein actuating the secondary pumpdraws a wellbore liquid into the secondary pump, pressurizes thewellbore liquid within the secondary pump, and discharges a pressurizedwellbore liquid into the production tubing for production to a surfacelocation.
 10. The well system of claim 9, further comprising one or moresensors in communication with the control system and operable to detectone or more downhole parameters, wherein operation of the pump is basedon one or more signals received from the one or more sensors.
 11. Thewell system of claim 9, wherein the solid state actuator is selectedfrom the group consisting of a piezoelectric actuator, anelectrostrictive actuator, a magnetorestrictive actuator, and anycombination thereof.
 12. The well system of claim 9, wherein thesecondary pump comprises one or more expansion pumps, and each expansionpump includes an expansion tank and an expandable member positionedwithin the expansion tank.
 13. The well system of claim 12, wherein theexpandable member comprises at least one of an elastomer bladder and ametal bellows.
 14. The well system of claim 12, wherein the one or moreexpansion pumps comprise a first expansion pump and a second expansionpump, the well system further comprising a switching valve arranged inthe fluid circuit to coordinate hydraulic fluid flow between the solidstate pump and the first and second expansion pumps.
 15. The well systemof claim 9, wherein the secondary pump comprises: a hydraulic motor influid communication with the solid state pump to receive the hydraulicfluid and thereby rotate a drive shaft; and a fluid pump operativelycoupled to the hydraulic motor via the drive shaft, wherein the wellboreliquid is drawn into the fluid pump and pressurized upon rotation of thedrive shaft.
 16. The well system of claim 15, wherein the fluid pumpcomprises a pump selected from the group consisting of a centrifugalpump, a rotary screw pump, a rotary lobe pump, a gerotor pump, aprogressive cavity pump, and any combination thereof.
 17. A method,comprising: positioning a pump within production tubing extended withina wellbore, the pump including a solid state pump having a solid stateactuator, and a secondary pump in fluid communication with the solidstate pump via a fluid circuit; actuating the solid state actuator andthereby conveying a hydraulic fluid to the secondary pump via the fluidcircuit; actuating the secondary pump with the hydraulic fluid receivedfrom the solid state pump and thereby drawing a wellbore liquid into thesecondary pump and pressurizing the wellbore liquid within the secondarypump; discharging a pressurized wellbore liquid from the secondary pumpand into the production tubing for production to a surface location; andcontrolling operation of the pump with a control system communicablycoupled to the pump.
 18. The method of claim 17, further comprisingdetecting one or more downhole parameters with one or more sensors incommunication with the control system; and controlling operation of thepump based at least partially on one or more signals received from theone or more sensors.
 19. The method of claim 17, wherein the secondarypump comprises a first expansion pump and a second expansion pump, andwherein a switching valve is arranged in the fluid circuit, the methodfurther comprising operating the switching valve to coordinate hydraulicfluid flow between the solid state pump and the first and secondexpansion pumps.
 20. The method of claim 17, wherein the secondary pumpcomprises a hydraulic motor in fluid communication with the solid statepump, and a fluid pump operatively coupled to the hydraulic motor at adrive shaft extended from the hydraulic motor, the method furthercomprising: receiving the hydraulic fluid from the solid state pump atthe hydraulic motor and thereby rotating the drive shaft; and drawingthe wellbore liquid into the fluid pump upon rotation of the driveshaft, and thereby pressurizing the wellbore liquid.